Exelon Corporation

Christopher Crane

President and Chief Operating Officer

Edison Electric Institute Financial Conference

November 10-12, 2008

EXHIBIT 99.1

2

Forward-Looking Statements

This presentation includes forward-looking statements within the meaning of the Private Securities

Litigation Reform Act of 1995. These forward-looking statements include, for example, statements

regarding benefits of the proposed merger, integration plans and expected synergies.  There are a

number of risks and uncertainties that could cause actual results to differ materially from the forward-

looking statements made herein.   The factors that could cause actual results to differ materially from

these forward-looking statements include Exelon’s ability to achieve the synergies contemplated by the

proposed transaction, Exelon’s ability to promptly and effectively integrate the businesses of NRG and

Exelon, and the timing to consummate the proposed transaction and obtain required regulatory

approvals as well as those discussed in (1) Exelon’s 2007 Annual Report on Form 10-K in (a) ITEM 1A.

Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of

Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 19; (2) Exelon’s Third

Quarter 2008 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors

and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 12; and (3) other factors

discussed in Exelon’s filings with the SEC.  Readers are cautioned not to place undue reliance on

these forward-looking statements, which apply only as of the date of this filing.  Exelon does not

undertake any obligation to publicly release any revision to its forward-looking statements to reflect

events or circumstances after the date of this filing.

All information in this presentation concerning NRG, including its business, operations, and financial

results, was obtained from public sources.  While Exelon has no knowledge that any such information

is inaccurate or incomplete, Exelon has not had the opportunity to verify any of that information.

3

Important Additional Information

This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities

or a solicitation of any vote or approval.  This presentation relates to a transaction with NRG proposed

by Exelon, which may become the subject of a registration statement filed with the Securities and

Exchange Commission (the “SEC”).  This material is not a substitute for the prospectus/proxy statement

Exelon intends to file with the SEC regarding the proposed transaction or for any other document which

Exelon may file with the SEC and send to Exelon or NRG stockholders in connection with the proposed

transaction. INVESTORS AND SECURITY HOLDERS OF EXELON AND NRG ARE URGED TO

READ ANY SUCH DOCUMENTS FILED WITH THE SEC CAREFULLY IN THEIR ENTIRETY WHEN

THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION

ABOUT THE PROPOSED TRANSACTION.

Exelon and its directors and executive officers and other persons may be deemed to be participants in

the solicitation of proxies in respect of the proposed transaction.  Information regarding Exelon’s

directors and executive officers is available in its Annual Report on Form 10-K for the year ended

December 31, 2007, which was filed with the SEC on February 7, 2008, and its proxy statement for its

2008 Annual Meeting of Shareholders, which was filed with the SEC on March 20, 2008.  Other

information regarding the participants in a proxy solicitation and a description of their direct and indirect

interests, by security holdings or otherwise, will be contained in a proxy statement filed in connection

with the proposed transaction.

4

Exelon Key Messages

•

Consistent with Exelon Protect and

Grow Strategy

•

Earnings and cash accretion

•

Clear value creation

•

Meets NRG’s “Five Imperatives”

Exelon Financial

Outlook

•

2009 operating guidance of $4.00 -

$4.30/share

•

Managing costs and driving productivity

•

Significant uplift in 2011 -

operating

earnings of ~$5.00-$6.00/share

(1)

(1) 

Illustrative.  Provided solely to illustrate possible future outcomes that are based on a number of different assumptions, all of which are subject to

uncertainties and should not be relied upon as earnings guidance or a forecast of future results.

Compelling Offer

for NRG

5

A Compelling Opportunity for Value Creation

•

Exelon offered to acquire all outstanding common shares of NRG

in an all stock transaction

–

Fixed exchange ratio of 0.485 Exelon share for each NRG common share

–

Offer

represents

a

37%

premium

to

October

17th

closing

price

for

NRG

•

Combined Entity Creates Value By:

–

Providing earnings and cash accretion

–

Creating an exceptional growth platform

–

Operating in the most attractive

markets

–

Utilizing a premier balance sheet

–

Allowing Exelon to unlock NRG’s value

–

Giving NRG’s shareholders the

opportunity to participate in future value

–

Presenting manageable regulatory

hurdles to close

6

Transaction Is Accretive

(1)

Does not include purchase accounting. One-time cost to achieve of ~$100 million (pre-tax) and transaction and other costs of $654 million excluded.

(2)

Free

cash flow defined as cash flow from operations less capital expenditures.

(3)

Based solely on I/B/E/S estimates for Exelon and NRG as of 10/31/08.  Not necessarily representative of either company’s internal forecasts.  Provided for

illustration only.  Not intended as earnings guidance or as a forecast of expected results.

(4) 

Assumes refinancing of ~$8 billion of NRG debt at an interest rate of 10%.

(5)

Pro forma numbers in Exelon’s internal forecasts are somewhat lower and accretion is approximately breakeven in 2011.

Operating Earnings

per

share

1

Free

cash

flow

2

per share

$3.82

$4.29

$4.69

2010E

2011E

2012E

$2.83

$2.91

$3.70

2010E

2011E

2012E

$3.04

N/A

N/A

2010E

2011E

2012E

$4.42

$5.86

$6.16

2010E

2011E

2012E

$4.03

N/A

N/A

2010E

2011E

2012E

32.5%

$4.83

$6.01

$6.43

2010E

2011E

2012E

9.4%

2.5%

4.3%

Based on analyst consensus estimates for both companies, the deal will be

accretive in the first full year following closing

Exelon 

NRG

Pro forma

5

•

Synergies

•

Increased interest

expense

(4)

•

Synergies

•

Increased interest

expense

(4)

3

3

1

2

7

Combination Creates

Substantial Synergies

Exelon

Operations & Maintenance:

$4,289

NRG

Maintenance & Other Opex:

$950

General & Admin Expenses:

$309

Other COGS:

$454

Pro Forma

Combined Non-fuel Expenses:    $6,002

Estimated

Annual

Cost

Savings:

$180

-

$300

2

% of Combined Expenses:

3%-5%

Costs to Achieve

$100

NPV of Synergies:

$1,500-$3,000

($ in Millions)

Reflects

no

revenue

or

fuel

cost

synergies.

Excludes transaction and other costs of $654 million and excludes increased interest expense related to refinancing of

NRG debt.

(1)

Company 10-K for 2007 and investor presentations.

(2)

Based on a preliminary analysis of publicly available information.  Subject to due diligence investigation.

1

Transaction

creates

$1.5

–

$3

billion

of

value

through

synergies

–

with

opportunity

for

more

1

Clear Value under Multiple Scenarios

Gas price is long-term price in 2008 $/MMBtu; coal price is long-term price in 2008 $/ton for PRB8800 excluding transportation; new build cost is long-term

combined

cycle

cost

in

PJM

in

2008

overnight

$/kW;

carbon

year

is

year

in

which

national

cap

and

trade

starts;

carbon

price

is

in

2012

$/tonne

assuming 7%

escalation; moderate recession assumes conditions consistent with current forward prices; and severe recession assumes five years of no load growth.

8

Gas Prices

New Build Costs

Carbon Year/Price

Recession

$0

$6.50

$1,300

Moderate

2014/$22

$7.30

$1,100

Moderate

2020/$22

$7.10

$1,100

Severe

2014/$22

$7.30

$1,500

Moderate

2012/$12

$8.60

$1,500

Moderate

We look at fundamental value creation under a wide range of future commodity

price scenarios and our analysis suggests $1-3 billion, possibly more

Coal Prices

$11.00

$20.00

$20.00

$20.00

$11.00

9

Without

Premium

0

1,000

3,000

2,000

With

Premium

Conservative

DCF Estimate

Replacement

Costs

NRG Stock Value

NRG Long-Term Value

975

1,350

2,050

3,000+

Price per Kilowatt Comparison for Texas Baseload Generation

Exelon Unlocks NRG Value

Less than 45% of

replacement value

Even with premium, purchase

price is 66% of conservative

long-term DCF value

subtracting

value

of

other

NRG

assets

from

NRG

enterprise

value

based

on

October

17

th

close.

$/KW

values are for 5,325 MW of Texas baseload

which includes Parish coal, Limestone, and STP; values implied by NRG stock price are determined by

10

World Class Nuclear & Fossil Operations

High performing nuclear plant

•

Top quartile capacity factor –

94.9%

•

Large, well-maintained, relatively young units

Fossil fleet

•

Half of >500 MW coal units are top quartile capacity factor

•

90% of coal fleet lower-cost PRB and lignite

NRG

Premier U.S. nuclear fleet

•

Best fleet capacity factor ~ 94%

•

Lowest fleet production costs ~ $15 /MWh

•

Shortest fleet average refueling outage duration –

24 days

•

Strong reputation for performance

Exelon

11

<1%

<1%

6%

Coal

Exelon

~150,000 GWh

Pro Forma

Exelon

~198,000 GWh

Nuclear

PRB & Lignite Coal

Other Coal

Gas/Oil

Hydro/Other

2009 Historical Forward Coal Prices

Combined Entity Will Continue to Benefit

from Low Cost, Low Volatility Fuel Sources

0.00

1.00

2.00

3.00

4.00

5.00

6.00

Powder River Basin

Northern Appalachian

Central Appalachian

Production Costs

0

2

4

6

8

10

12

2000

2001

2002

2003

2004

2005

2006

2007

Nuclear

Gas

Coal

Petroleum

93%

Nuclear

1%

3%

75%

Nuclear

15%

PRB &

Lignite Coal

6%

Other

Coal

(1)

Based on 2007 data, does not include ~38,000 GWh of Exelon Purchased Power.

Q1 2007

Q2 2007

Q3 2007

Q4 2007

Q1 2008

Q2 2008

Q3 2008

Powder River Basin and lignite coal supply (90% of NRG’s coal)

provides low-sulfur at a relatively stable price as compared to

northern and central Appalachian coal mines.

Combined fleet will continue to be

predominantly low-cost fuel.

1

1

0

50

100

150

50

100

150

200

250

2006 Electricity Generated (GWh, in thousands)

NRG

TVA

AEP

Duke

FPL

Southern

Exelon + NRG

Entergy

Exelon

Dominion

Progress

FirstEnergy

Bubble size represents carbon

intensity, expressed in terms of

metric tons of CO2 per MWh

generated

SOURCE: EIA and EPA data as compiled by NRDC

CO2 Emissions of Largest US Electricity Generators

Largest Fleet, 2nd Lowest

Carbon Intensity

Top Generators by CO2 Intensity

10

9

8

7

6

5

4

3

2

1

12

Exelon 2020 principles will be applied to the combined fleet

AEP

NRG

Southern

Duke

FirstEnergy

TVA

Progress

Dominion

FPL

Exelon + NRG

Entergy

Exelon

0.83

0.80

0.74

0.66

0.64

0.64

0.57

0.50

0.35

0.31

0.26

0.07

Financing Plan Considerations

•

Negotiated acquisition of NRG would require refinancing of only

~$4B of NRG debt and other credit facilities

–

Under a negotiated deal with NRG, $4.7B of NRG bonds

could remain in place with no change in terms, but with

substantially improved credit metrics for those bondholders

–

Exelon's relationships with many of NRG's banks should

facilitate arrangements for new credit facilities

–

Financing commitments are well underway for refinancing

•

The NRG direct lien program for power marketing could be left

in place

13

14

Premier Balance Sheet

and Credit Metrics

Committed to returning Exelon Generation’s senior unsecured debt

to strong investment grade within the next 3 years

Targeting

stronger

credit

metrics

for

the

combined

entity

--

25

-

30%

FFO/debt

Pay down debt plan will include: NRG balance sheet cash, asset

sale proceeds, free cash flow

Exelon

NRG

Today

2011

Credit Rating:

BBB

FFO / Debt:

25-30%

Combined

Entity

Targets

Credit Rating:

BBB-

FFO / Debt:

26%

Credit Rating:

B+

FFO / Debt:

18%

2

3

1

(1)

Ratios exclude securitized debt.

(2)

Senior unsecured credit rating and FFO/Debt as of 10/31/08.  Reflects S&P updated guidelines, which include imputed debt and interest related to purchase

power agreements, unfunded pension and other postretirement benefits obligations, capital adequacy for energy trading, operating lease obligations and

other off-balance sheet data. 

(3)

From Standard & Poor’s 8/28/08 CreditStats: Independent Power Producers & Energy Traders – U.S.

15

Principal Regulatory Approvals and

Expected Divestitures

•

Principal regulatory approvals:

–

Texas, New York, Pennsylvania, California state regulatory commissions

–

Hart-Scott-Rodino (DOJ/FTC)

–

FERC

–

NRC

–

Notice filing in Illinois

•

Limited

market

power

issues

–

not

expected

to

challenge

transaction

closing

–

Divestitures anticipated only in PJM and ERCOT

–

~3,200

MWs

of

high

heat

rate

gas

and

baseload

coal

plants  and

~1,200

MWs

under

contract

–

Model assumes $1 billion of proceeds from divestitures (after-tax)

Regulatory hurdles are manageable

1

(1)

Plants

subject

to

divestiture

are

de

minimus

contributors

to

revenue

and

earnings.

16

Exelon

More

Than

Meets

the

“Five

Imperatives”

Outlined by NRG on May 28, 2008

1.

1.

2.

2.

3.

3.

4.

4.

5.

5.

NRG’s Stated Imperatives

MUST

accumulate generation at competitive cost

This transaction accomplishes in one step what several

transactions might have accomplished for NRG in these

regards.  Given the current difficulty in accessing capital

markets, it is unclear whether NRG would have the

ability to meet this objective without Exelon.

Exelon provides NRG stakeholders with broad trading

expertise and sound power marketing and risk

management practices.  Exelon’s significant experience

in markets with locational prices is particularly relevant

since ERCOT is moving to a PJM-type structure.

Exelon’s breadth of operations and depth of service

allows unparalleled access to customers, retail

providers, and other sales channels.

NRG stakeholders become part of the most diversified

and competitive generation portfolio operating in 12

different states and 6 different regional transmission

organizations.

Deal provides NRG stakeholders with significant value

and upside and a share of the largest unregulated

generation fleet in the United States.

MUST

be geographically diversified in multiple

markets

MUST

develop and expand our route to market

through contracting with retail load providers, trading,

direct sales, etc

MUST

have sophisticated ability to trade, procure,

hedge, and originate for electricity and input fuels

MUST

develop depth and breadth in key markets,

particularly across fuel types, transmission

constraints and merit order

Exelon Combination More

than Meets These Imperatives

17

Exelon Key Messages

Compelling Offer

for NRG

•

Consistent with Exelon Protect and

Grow Strategy

•

Earnings and cash accretion

•

Clear value creation

•

Meets NRG’s “Five Imperatives”

Exelon Financial

Outlook

•

2009 operating guidance of $4.00 -

$4.30/share

•

Managing costs and driving productivity

•

Significant

uplift

in

2011

-

operating

earnings of ~$5.00-$6.00/share

(1)

(1)

Illustrative.

Provided solely to illustrate possible future outcomes that are based on a number of different assumptions, all of which are subject to

uncertainties

and

should

not

be

relied

upon

as

earnings

guidance

or

a

forecast

of

future

results.

18

Well-Positioned in Near-Term

Macroeconomic Uncertainty

•

Hedging strategy provides near-term earnings and cash flow

stability

•

Over 90% and 80% financially hedged in 2009 and 2010,

respectively

Risk management

•

Proven management team

•

Lowest-cost

nuclear

fleet

operator

with

~94%

capacity

factor

Best-in-class management /

operations

•

Nuclear remains a low-cost generation source

•

Improving

utilities’

performance

and

regulatory

environment

Basics of business unchanged

•

Nation’s

largest

nuclear

fleet

~140,000

GWhs

of

annual

production

Market leader

•

Progress made on transition to competitive markets in PA

•

ComEd

on path to regulatory recovery

•

Positively levered to long-term fundamentals

Long-term value in place

•

Strong

and

consistent

cash

flows

from

operations

–

~$4.75

billion estimated in 2009

•

Over 12% annual growth rate in dividend since 2001

Stable cash flows and

commitment to value return

•

~$6.8 billion of available credit facilities as of 10/31/2008

•

Debt

maturities

of

$29

million

(1)

,

in

total,

through

12/31/2009

Sufficient liquidity

Investment Criteria

Exelon Profile

(1)  Excludes securitization debt.

19

O&M and other

Inflation

Pension/OPEB

Cost initiatives

Bad debt expense

2009 Operating Earnings Guidance

2009E

2008E

$0.45 -

$0.50

$3.45 -

$3.55

$4.15 -

$4.30

(1)

ComEd

PECO

Exelon

Generation

2009 Earnings Drivers

ComEd

PECO

Exelon

Generation

Holdco

Holdco

Exelon

$0.30 -

$0.35

Exelon

$4.00 -

$4.30

(1)

$0.45 -

$0.55

$0.45 -

$0.55

$3.10 -

$3.35

NOTE:  See “Key Assumptions”

slide in Appendix

(1)  Operating Earnings Guidance.  Excludes the earnings impact of certain items as disclosed in the Appendix.

(2)  Primarily

reflects

2008

option

and

uranium

settlement

gains

at

Exelon

Generation.

Issuing 2009 operating earnings guidance of $4.00-$4.30/share

(1)

ComEd

distribution revenue

PECO gas revenue

Nuclear fuel costs

Depreciation and amortization

PECO CTC

Discrete 2008 ExGen

gains

(2)

20

Exelon Cost and Capital Management

Initiative

•

Clearly define governance and oversight model

•

Optimize the Exelon operational structure to drive efficiency and accountability,

reducing complexity and cost

•

Provide better visibility on cost drivers and productivity

•

Process improvement and elimination of low value work

•

Drive productivity focus in business planning process

Define and implement

appropriate governance and

oversight model

Identify cost reduction

opportunities

Focus 1:  Cost

Break-through

Drive focus on productivity

initiatives

Identify additional needs and

opportunities

Focus 2:  Business Unit

Cost Productivity

Process redesign

Systems investment

Focus 3:  Sustainable

Productivity

Drive productivity and cost reduction (with continued superior operations)

Cost and capital

management initiatives support earnings expectations

21

Exelon Key Messages

•

Consistent with Exelon Protect and

Grow Strategy

•

Earnings and cash accretion

•

Clear value creation

•

Meets NRG’s “Five Imperatives”

Exelon Financial

Outlook

•

2009 operating guidance of $4.00 -

$4.30/share

•

Managing costs and driving productivity

•

Significant uplift in 2011 -

operating

earnings of ~$5.00-$6.00/share

(1)

(1) 

Illustrative.  Provided solely to illustrate possible future outcomes that are based on a number of different assumptions, all of which are subject to

uncertainties and should not be relied upon as earnings guidance or aforecast of future results.

Compelling Offer

for NRG

22

Appendix

Additional Information regarding Offer

for NRG

23

Pro Forma

Exelon

Combined company will have requisite scope,

scale and financial strength to succeed in an

increasingly volatile energy market

Combination Will Result in Scope,

Scale and Financial Strength

(1)

Reflects total assets (under GAAP) with no adjustments. Based upon 9/30/08 Form 10-Q.

(2)

Reflects Last Twelve Months EBITDA (Earnings before Income Taxes, Depreciation and Amortization) as of 9/30/08 with no adjustments.

(3)

Calculation

of

Enterprise

Value

=

Market

Capitalization

(as

of

10/31/08)

+

Total

Debt

(as

of

6/30/08)

+

Preferred

Securities

(as

of

6/30/08)

+

Minority

Interest

(as of 6/30/08) –

Cash & Cash Equivalents (as of 6/30/08).

Debt, Preferred Securities, Minority Interest and Cash & Cash Equivalents based upon 6/30/08

Form 10-Q.

(4)

Includes

owned-and-contracted

capacity

after

giving

effect

to

planned

divestitures

after

regulatory

approvals.

$0

$30

$50

$60

$40

$20

$70

$10

Southern

Dominion

FPL

Duke

First

Energy

Entergy

$68,900

Combined assets

(1)

$9,400

LTM EBITDA

(2)

($ in millions)

$63,000

Enterprise value

(3)

~51,000MWs

Generating capacity

(4)

Pro Forma Quick Stats

Market cap (as of 10/31/08)

$41,200

Combination Enables Access to

Attractive New Markets

By RTO

Combined  

PJM

22,812

ERCOT

13,027

MISO

1,065

ISO NE

2,174

NYISO

3,960

CAL ISO

2,085

Contracted*

6,280

51,403

SERC

2,405

WECC

45

Total

53,853

By Fuel Type

Combined

Nuclear

18,144

Coal

8,986

Gas/Oil

18,801

Other

1,642

Contracted

6,280

*Contracted in various RTOs, mainly in PJM and ERCOT

(1)

Excludes international assets. Before any divestitures.

24

Geographically complementary asset base 

Attractive new markets for Exelon (NY, NE,

CA): declining reserve margins, supportive

regulatory structures

Predominantly located in competitive

markets

ERCOT portfolio will position Exelon to offer

an array of products, capture value, and

efficiently utilize credit

1

1

Exelon

NRG

25

Nuclear Growth Opportunities

•

Texas offers nuclear growth platform

•

Potential for stretch power uprate

(5-7%) on South Texas

Project units 1 and 2

•

Construction & Operating License and Loan Guarantee

applications filed for both STP 3 and 4 and Victoria County

•

Exelon has the financial strength and discipline to investigate

these opportunities

•

Strong balance sheet and credit metrics

•

Demonstrated track record of financial rigor

•

Nuclear depth and expertise

•

Options to build remain under evaluation; no commitment

has yet been made

26

Exelon 2020 and NRG

•

Expand internal energy efficiency, SF6,

vehicle, and supply chain initiatives to NRG

portfolio

•

Offset a portion of NRG’s GHG emissions

•

Expand energy efficiency program offerings

•

Add capacity to existing nuclear units

through uprates

•

Add new renewable generation

•

Add new gas-fired capacity

•

Continue to explore new nuclear

•

Address older/higher emitting coal

and oil units

•

Invest in clean coal technology R&D

Options to Evaluate:     

Taking the next step in Exelon’s

commitment to address climate change

Offer more low

carbon electricity in

the marketplace

Reduce emissions

from coal/oil fired

generation

Help our customers

and the communities

we serve reduce their

GHG emissions

Reduce or offset our

footprint by greening

our operations

Apply Elements of

Exelon 2020 to

NRG

Expand the 2020

Plan

27

NRG is Best Investment Available

0%

4.0%

8.0%

12.0%

16.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

(10.0%)

0%

5.0%

20.0%

EBITDA / EV Yield

Earnings Yield

Free Cash Flow

Yield

EXC

Illustrative

Utilities 

NRG at

Offer

2009E

2010E

7.9

10.2

11.8

10.6

8.1

11.4

11.9

10.7

IPPs

EXC

Illustrative

Utilities 

NRG at

Offer

IPPs

EXC

Illustrative

Utilities 

NRG at

Offer

IPPs

13.7

15.4

20.1

16.7

14.4

16.1

20.1

17.1

Source: FactSet. Prices as of 10/17/08, I/B/E/S estimates as of 10/31/08.

EV = Enterprise Value

(1)

Illustrative Utilities include CMS, CNL, DPL, TE, WEC, WR.

(2)

IPPs include CPN, DYN, MIR, RRI.

4.3

(3.1)

11.2

11.6

5.2

(6.2)

14.2

12.3

15.0%

10.0%

(5.0%)

1

2

2

2

1

1

28

2009 Financial Outlook and

Operating Data

29

The Exelon Companies

’07 Earnings:

$2,331M 

’07 EPS:

$3.45

Total Debt

(1)

:

$2.5B

Credit Rating

(2)

:

BBB

Nuclear, Fossil, Hydro & Renewable Generation

Power Marketing

‘07 Operating Earnings:

$2.9B

‘07 EPS:

$4.32

Assets

(1)

:                        

$45.2B

Total Debt

(1)

:

$13.0B

Credit Rating

(2)

:                            BBB-

Note: All ’07 income numbers represent adjusted (Non-GAAP) Operating Earnings and EPS. Refer to Appendix for reconciliation of adjusted (non-GAAP) operating EPS to

GAAP EPS.

(1)

As of 9/30/08.

(2)

Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and senior secured debt ratings for ComEd and PECO as of 10/31/08.

Pennsylvania

Utility

Illinois

Utility

’07 Earnings:

$200M

$507M

’07 EPS:

$0.30

$0.75

Total Debt

(1)

:

$5.1B

$3.5B

Credit Ratings

(2)

:

BBB+

A-

30

Multi-Regional, Diverse Company

Note: Owned megawatts based on Generation’s ownership, using

annual mean ratings for nuclear units (excluding Salem) and

summer ratings for Salem and the fossil and hydro units.

Midwest Capacity

Owned:

11,388 MW

Contracted:

3,230 MW

Total:

14,618 MW

ERCOT/South Capacity

Owned:

2,222 MW

Contracted:

2,917 MW

Total:

5,139 MW

New England Capacity

Owned:

194 MW

Total Capacity

Owned:

24,821 MW

Contracted:

6,483 MW

Total:

31,304 MW

Electricity Customers:

1.6M

Gas Customers: 

0.5M

Electricity Customers:  3.8M

Generating Plants             

Nuclear

Hydro

Coal/Oil/Gas Base-load

Intermediate

Peaker

Mid-Atlantic Capacity

Owned:

11,017 MW

Contracted:

336 MW

Total:

11,353 MW

31

~4%

(2)

$1,050

$1,100

~3%

(2)

$700

$750

~4%

~4%

2009-2013 CAGR

$4,400

$2,650

2009E

$4,500

$2,700

2008E

Exelon

(3)

O&M Expense

(1)

($ in Millions)

O&M and CapEx Expectations

($ in Millions)

~5%

$1,000

$950

~6%

$400

$400

Exelon

(3)

~4%

~8%

~3%

2009-2013 CAGR

(4)

$3,400

$950

$1,000

2009E

$3,300

$850

$950

2008E

Nuclear

Fuel

Plant &

Other

CapEx

A combination of company-wide cost-savings initiatives and controlled spending will offset

inflationary

pressures

and

rising

pension

and

retiree

health

and

welfare

costs

(1)

Reflects Operating O&M data and excludes Decommissioning impact.

(2)

For ComEd and PECO, O&M excludes energy efficiency spend recoverable under a rider. 2009-2013 Compound Annual Growth Rate (CAGR) would be ~6% for

ComEd and ~4% for PECO if spend was included.

(3)

Includes eliminations and other corporate entities.

(4)

Subject to change based upon proposed NRG acquisition.

NOTE:

CapEx

expectations

for

ComEd

exclude

potential

investment

in

automated

meter

technology

that

is

subject

to

approval

by

the

Illinois

Commerce

Commission.

32

2009 Projected Sources and Uses of Cash

150

0

300

50

Other

(4)

150

350

(250)

250

Net Financing (excluding Dividend):

(2)

750

350

200

200

Planned Debt Issuances

Net Financing (excluding Dividend):

(2)

(750)

0

(750)

0

Planned Debt Retirements

(3)

$4,750

$2,800

$950

$1,000

Cash Flow from Operations

(1)

(3,400)

(1,950)

(400)

(1,000)

Capital Expenditures

$1,500

$1,200

$300

$250

Cash Available before Dividend

(1,400)

Dividend

(5)

$100

Cash Available after Dividend

Exelon

(6)

($ in Millions)

Numbers are rounded and may not add.

(1)

Cash Flow from Operations = Primarily includes net cash flows provided by operating activities, excluding counterparty collateral activity, and including net cash flows used in

investing activities other than capital expenditures.  

(2)

Net Financing (excluding Dividend) = Net cash flows used in financing activities excluding dividends paid on common and preferred stock.

(3)

Planned Debt Retirements are $17M, $728M, and $11M for ComEd, PECO, and ExGen, respectively.  Includes securitized debt.

(4)

Other financing includes ComEd recovery of excess payments to ComEd Transitional Funding Trust.  For PECO it represents the Parent Receivable and expected changes in

short-term debt.

(5)

Assumes

2009

Dividend

of

$2.10

per

share.

Dividends

are

subject

to

declaration

by

the

board

of

directors.

(6)

Includes cash flow activity from Holding Company, eliminations, and other corporate entities.

33

Pension Benefit Expense

Service

Amortization

Interest

Expected

Return on

Assets

Total

Service

50 bps

~$40M

Long-Term Expected

Return on Plan Assets

(EROA)

50 bps

~$37M

100 bps

~$2.5M

Sensitivity of 2009 pre-tax

pension expense

12/31/08 Discount Rate

FY08 Asset Returns

Impact on 2009

estimated expense

Input

Pension Plan Key

Metrics –

12/31/07   

(in millions)

Assets

$9,634

Obligations

$10,427

Discount rate

6.20%

2008 L-T EROA

8.75%

$130

$83

($668)

$113

$508

$0

$200

$400

$600

$800

Note: Excludes settlement charges.

34

Other

Postretirement

Benefits

(OPEB)

2009

Expense:

Exelon

estimates

pre-tax

2009

OPEB

expense

of

~$175

million

under

Scenarios

1-3

and

$225

million

under

Scenario

4

as

compared

to

$160

million

in

2008.

2009 Contributions:

Exelon estimates roughly $150 million of contributions to its OPEB plans in 2009, which is subject to

change.

Potential Variability in Future Pension

Expense and Contributions

Required

contribution

Pre-tax

expense

Required

contribution

Pre-tax

expense

Required

contribution

Pre-tax

expense

Discount Rate

Actual Asset

Returns

$1,375

$300

$825

$250

$175

$150

6.70% as of 1/1/09,

increasing to 6.90%

as of 1/1/11

-27% in 2008

-15% in 2009

-3% in 2010

8.5%in 2011

4

$775

$275

$225

$200

$125

$75

7.90% as of 1/1/09,

increasing to 8.10%

as of 1/1/11

-27% in 2008

-15% in 2009

-3% in 2010

8.5%in 2011

3

$675

$250

$200

$175

$125

$75

7.90% as of 1/1/09,

increasing to 8.10%

as of 1/1/11

-27% in 2008

-9% in 2009

8.5% in 2010-

2011

2

$100

$225

$100

$150

$125

$75

7.90% as of 1/1/09,

increasing to 8.10%

as of 1/1/11

-27% in 2008

8.50% in 2009-

2011

1

2011

2010

2009

Assumptions

Illustrative

Scenario

NOTE:  Slide provided for illustrative purposes and not intended to represent a forecast of future outcomes. Assumes 20% overall capitalization rate of pension and OPEB costs.

35

Sufficient Liquidity

(1)

Excludes previous commitment from Lehman Brothers Bank.

(2)

Available Capacity Under Facility represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit.  The amount of

commercial paper outstanding does not reduce the available capacity under the credit agreements.

(3) 

Includes cash flow activity from Holding Company, eliminations, and other corporate entities.

(90)

--

--

(90)

Outstanding Facility Draws

(416)

(155)

(90)

(166)

Outstanding Letters of Credit

$7,317

$4,834

$574

$952

Aggregate Bank Commitments

(1)

6,811

4,679

484

696

Available Capacity Under Facility

(2)

--

--

--

--

Outstanding Commercial Paper

$6,811

$4,679

$484

$696

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ in Millions)

We

have

no

commercial

paper

outstanding

and

our

bank

facility

is

largely

untapped

Available Capacity Under Bank Facility as of October 31, 2008

36

Large and Diverse Bank Group

Exelon

has

a

large

and

diverse

bank

group

with

over

$7.3

billion

in

aggregate

credit

facility commitments –

24 banks committed to the facility with each bank having less than

10% of the aggregate commitments at Exelon

•

Bank of America, N.A. / Merrill Lynch USA

(2)

•

The Royal Bank of Scotland PLC (RBS)

•

Barclays Bank PLC

•

JP Morgan Chase Bank, N.A.

•

The Bank of Nova Scotia (Scotia)

•

Wachovia Bank, N.A.

•

Citibank, N.A.

•

Commerzbank

AG

•

BNP Paribas

•

Deutsche Bank AG, New York Branch

•

Credit Suisse, Cayman Islands Branch

•

Morgan Stanley Bank

•

UBS Loan Finance LLC

•

The Bank of New York / Mellon Bank, N.A.

•

Mizuho Corporate Bank, LTD

•

Goldman Sachs

(3)

•

The Bank of Tokyo-Mitsubishi UFJ, LTD

•

KeyBank

N.A.

•

U.S. Bank, N.A.

•

SunTrust Bank

•

Union Bank of California, N.A.

•

The Northern Trust Company

•

Malayan Banking Berhad

(May Bank)

•

National City Bank

(1)

As

of

October

31,

2008.

(2)

Assumes

that

Bank

of

America

assumes

Merrill

Lynch’s

previous

commitment.

(3)

Includes

funding

commitments

by

Williams

Street

Commitment

Corporation,

Williams

Street

Credit

Corporation,

Goldman

Sachs

Credit

Partners,

L.P.

Banks Committed to Exelon’s Facilities

(1)

37

$0

$150

$300

$450

$600

$750

2009

2010

2011

2012

2013

Exelon Corp

Exelon Generation

ComEd

PECO

2009-2013 Debt Maturities

Note: Balances shown exclude securitized debt

Minimal debt maturities before 2011

$29 M

Total

$615 M

Total

$1,799 M

Total

$828 M

Total

$255 M

Total

38

Stable Cash Flows and Commitment to

Value Return

(1) Cash Flows from Operations primarily include net cash flows provided by operating activities, excluding counterparty collateral activity, and including net cash flows used

in investing activities other than capital expenditures.  Cash Flows from Operations in 2005 reflect discretionary aggregate pension contributions of $2 billion.

Exelon produces strong and consistent cash flows and continues to honor its commitment to

return value to shareholders

Strong and consistent

cash flows from

operations

(1)

Over 12% compound

annual dividend growth

rate since 2001

Sustainable Value

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

2001

2002

2003

2004

2005

2006

2007

2008E

2009E

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

Cash flow from operations

Annual cash dividend / share

39

Value Return Framework

Less

Equals

Maintenance Capital and Committed Dividends

Free Cash Flow before Dividends and CapEx

Strengthen Balance Sheet /

Increase Financial Flexibility

Invest in Growth

Available

Cash

and

Balance

Sheet

Capacity

(1)

Return Value via

Share Repurchases,

Increased Dividends

Monetize

We evaluate value return on an annual basis

(1)

Exelon on a stand alone basis targets a FFO/Debt Ratio of 20-30%.

40

Protect Today’s Value

•

Deliver superior operating

performance

•

Advance competitive markets

•

Protect the value of our generation

•

Build healthy, self-sustaining

delivery companies

Grow Long-Term Value

•

Drive the organization to the next

level of performance

•

Set the industry standard for low

carbon energy generation and

delivery through reductions,

displacement and offsets

•

Rigorously evaluate and pursue

new growth opportunities

+

Strategic Direction

41

42

Exelon Generation 2009 EPS Contribution

Generation’s 2009 earnings will be impacted by higher nuclear fuel expense and the

absence

of

discrete

gains

reported

in

2008

–

cost

savings

initiatives

will

partially

offset

inflationary

pressures

and

rising

pension

and

retiree

health

and

welfare

costs

(1) 

Estimated contribution to Exelon’s operating earnings guidance.

(2) 

Primarily

reflects

uranium

settlements

and

option

gains

reported

in

2Q08.

($0.18)

$0.02

($0.01)

RNF

O&M

Other

Depreciation

($0.06)

$ / Share

Key Items:

Cost Efficiency Initiative

Nuclear Outages

Inflation

Pension & OPEB

2008e

(1)

2009e

(1)

$3.10 –

$3.35

$3.45 –

$3.55

Key Items:

Discrete

2008

Gains

(2)

($0.14)

Nuclear Fuel Expense   

($0.08)

$0.06

$0.03

($0.07)

($0.04)

43

•

Large, low-cost, low-emissions,

exceptionally well-run nuclear fleet

•

Complementary and flexible fossil and

hydro fleet

•

Improving power market fundamentals

(commodity prices, heat rates, and

capacity values)

•

End of below-market contract in

Pennsylvania beginning 2011

•

Potential carbon restrictions

Value Proposition

Exelon Generation

•

Continue to focus on operating excellence,

cost management, and market discipline

•

Execute on power and fuel hedging

programs

•

Support competitive markets

•

Pursue nuclear & hydro plant relicensing

and strategic investment in material

condition

•

Maintain industry-leading talent

Protect Value

•

Pursue potential for nuclear plant uprates

and investigate potential for more

•

Rigorously evaluate generation

development opportunities, including new

nuclear and combined cycle gas turbine

•

Capture increased value of low-carbon

generation portfolio

Grow Value

Exelon

Generation

is

the

premier

unregulated

generation

company

–

positioned to

capture market opportunities and manage risk

44

Basics of Business Unchanged

Nuclear remains one of the lowest cost options for electricity production

10.26

6.78

2.47

1.76

0.0

2.0

4.0

6.0

8.0

10.0

12.0

2000

2001

2002

2003

2004

2005

2006

2007

Petroleum

Gas

Coal

Nuclear

U.S. Electricity Production Costs

(2000-2007)

(1)

(1)

In 2007 Cents/kWh.  Source Global Energy Decisions May 2008;  Production Costs = Operations and Maintenance + Fuel Costs

45

Lowest Cost Nuclear Fleet Operator

Among major nuclear plant fleet operators, Exelon is consistently the lowest-cost

producer of electricity in the nation

1

st

Quartile

2

nd

Quartile

3

rd

Quartile

4

th

Quartile

2006-2007 Average Production Cost

for

Major

Nuclear

Operators

(1)

Average

(1)

Source:

2007

Electric

Utility

Cost

Group

(EUCG)

survey.

Includes

Fuel

Cost

plus

Direct

O&M

divided

by

net

generation.

46

Effectively Managing Nuclear Fuel Costs

Components of Fuel Expense in 2008

Projected Total Nuclear Fuel Spend

Projected Exelon Average Uranium Cost vs. Market

Projected Exelon Uranium Demand

Note: Excludes costs reimbursed under the settlement agreement with the DOE.

Market

source:

UxC

composite

forecasts.

2008

–

2011:

100% hedged in volume

2012:

~80% hedged in volume

2013:

~70% hedged in volume

All charts exclude Salem

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

2008

2009

2010

2011

2012

2013

0

200

400

600

800

1,000

1,200

1,400

2008

2009

2010

2011

2012

2013

Nuclear Fuel Expense (Amortization + Spent Fuel)

Nuclear Fuel Capex

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2008

2009

2010

2011

2012

2013

Exelon Average Reload Price

Projected Market Price (Term)

Enrichment

38%

Fabrication

17%

Nuclear Waste

Fund

22%

Tax/Interest

1%

Conversion

3%

Uranium

19%

47

Uranium Price Volatility

Long-term Uranium Price Trend

Long-term equilibrium price expected to be $40-$60/lb

Eighteen-Month Uranium Price

Trend

Long-term Uranium Price Trend

Spring 2003

McArthur River

flood

December 2003

GNSS/Tenex

termination;

ConverDyn

UF6 release

and shutdown

Early 2004

ERA / Ranger

water problems

Early 2006

First Cigar Lake flood;

Cyclone Monica halts 

ERA /  Ranger

operations for

approximately two

weeks

October 2006

Second Cigar

Lake flood

March 2007

ERA / Ranger flooding

(cyclone George)

0

20

40

60

80

100

120

140

160

0

20

40

60

80

100

120

140

160

48

World-Class Nuclear Operator

Average Capacity Factor

Note: Exelon data prior to 2000 represent ComEd-only nuclear fleet.

Sources:

Platt’s,

Nuclear

News,

Nuclear

Energy

Institute

and

Energy

Information

Administration

(Department

of

Energy).

65

70

75

80

85

90

95

100

Operator (# of Reactors)

Range

5-Year Average

Range of Fleet 2-Yr Avg Capacity Factor (2003-2007)

EXC 93.5%

Sustained production excellence

40%

50%

60%

70%

80%

90%

100%

Exelon

Industry

49

Impact of Refueling Outages

125

127

129

131

133

135

137

139

141

143

145

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

7

8

9

10

11

12

13

Note:  Data

includes

Salem.

Net

nuclear

generation

data

based

on

ownership

interest

•

18 or 24 months

•

Duration: ~24 days

Nuclear Refueling Cycle

•

Reflects

extended

steam

generator

replacement outage

•

Based on the refueling cycle, we will

conduct 10 refueling outages in 2009,

versus 12 in 2008

2009 Refueling Outage Impact

Refueling Outage Duration

Nuclear Output

0

10

20

30

40

50

60

2000

2001

2002

2003

2004

2005

2006

2007

2008

YTD

Exelon

Industry (w/o Exelon)

Actual

Target

Estimate

•

2008 reflects Salem’s extended

steam generator replacement outage.

•

2008 YTD average outage duration is

24 days without Salem

2008 Refueling Outage Impact

50

108,300

102,900

23,700

19,500

13,900

41,800

41,100

5,200

0

50,000

100,000

150,000

200,000

2008

2009

ComEd Swap

IL Auction

PECO Load

Actual Forward Hedges & Open Position

Total Portfolio Characteristics

Expected Total Supply (GWh)

Expected Total Sales

(GWh)

91,500

91,300

47,700

47,600

28,600

10,200

10,600

28,900

0

50,000

100,000

150,000

200,000

2008

2009

Forward / Spot Purchases

Fossil & Hydro

Mid-Atlantic Nuclear

Midwest Nuclear

178,300

178,300

178,100

178,100

51

Hedging Targets

(1)

Percent financially hedged is our estimate of the gross margin that is hedged at a 95% confidence level given the current assessment of market volatility.  The

formula

is

the

gross

margin

at

the

5th

percentile

/

expected

gross

margin.

Power Team utilizes various products and

channels to market in order to optimize

Exelon Generation’s earnings:

•

Block product sales in power

•

Options in power and natural gas

•

Full requirements sales via retail channel and

wholesale load procurement processes

•

Supplement the portfolio with structured

transactions

•

Use physical and financial fuel products to

manage variability in fossil generation output

Target Ranges

90% -

98%

70% -

90%

60% -

80%

>90%

Current Position

>80%

Near top end of

range

Prompt Year

(2009)

Second Year

(2010)

Third Year

(2011)

Financial

Hedging

Range

(1)

Flexibility in our targeted financial hedge ranges allows us to be opportunistic while

mitigating downside risk

Financial hedge ratios reflect a range of

revenue net fuel based on observed

market prices and volatility

•

Generally, hedges are executed on a ratable

basis over a three-year window; therefore, the

position is well hedged in the front year and

significantly open in the outer years

•

Utilize options to hedge risk and preserve

upside

52

Financial Swap Agreement with ComEd

3,000

$53.48

January 1, 2013 -

May 31, 2013

3,000

$52.37

January 1, 2012 -

December 31, 2012

3,000

$51.26

January 1, 2011 -

December 31, 2011

3,000

$50.15

June 1, 2010 -

December 31, 2010

2,000

$50.15

January 1, 2010 -

May 31, 2010

2,000

$49.04

June 1, 2009 -

December 31, 2009

1,000

$49.04

January 1, 2009 -

May 31, 2009

1,000

$47.93

June 1, 2008 -

December 31, 2008

Notional Quantity (MW)

Fixed Price ($/MWH)

Portion of Term

•

Market-based contract for ATC baseload energy only

–

Does not include capacity, ancillary services or congestion

•

Preserves competitive markets

•

Fits with Exelon Generation’s hedging policy and strategy

•

Small portion of Exelon Generation’s supply

53

Exelon Generation Has Limited

Counterparty Exposure

Net

Exposure

After

Credit

Collateral

(1)

(in millions)

Investment grade

$582

Non-investment grade

59

No external ratings

42

Total

$683

(1)

As

of

September

30,

2008.

Does

not

include

credit

risk

exposure

from

uranium

procurement

contracts

or

exposure

through

Regional

Transmission

Organizations,

Independent System Operators and New York Mercantile Exchange and Intercontinental Exchange commodity exchanges.  Additionally, does not include

receivables related to the supplier forward agreements with ComEd and the PPA with PECO. 

As of September 30

th

, no one counterparty represented more than 10% of Exelon

Generation’s net exposure from power marketing activities

Exelon

Generation

–

Sufficient

Liquidity

Aggregate credit facility commitments of $4.8

billion

that

extend

through

2012

–

$4.7

billion

available as of 10/31/08

Strong

balance

sheet

–

A3/BBB/BBB+

Senior

Unsecured Rating

Net

Exposure

by

Type

of

Counterparty

(1)

Coal

Producers

13%

Financial Institutions

45%

Investor-Owned Utilities,

Marketers, and

Power Producers

38%

Other

4%

54

Long-Term Investment Thesis

Power Market Fundamentals

Reserve Margins

Capacity Prices

Construction Costs

Commodities

Natural Gas

Coal

Environmental Position

Carbon

SO-2, NOX

Mercury

Lowest-cost,

low-emissions

nuclear fleet

Demand Trends

Demand Profile Changes

Off-Peak Usage

55

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

2008

2009

2010

2011

2012

2013

Reserve Margins Declining

Natural Gas Prices Remaining High

PJM-East

ERCOT

NI-Hub

PJM West

Positively Exposed to Market Dynamics

NYMEX

(1)

$5

$6

$7

$8

$9

$10

$11

$12

$13

2008

2010

2012

2014

2016

2018

2020

(1) As of 09/30/08

Various

3

rd

party

estimates

2,000

2,500

3,000

3,500

4,000

4,500

2007

2008

Note:  Illustrative estimate. Overnight, all-in capital cost without interest during construction.

Carbon Legislation Progressing

Construction Costs Escalating

New Nuclear Installed Cost

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

0

5

10

15

20

25

30

35

40

45

0

5

10

15

20

25

30

Carbon Credit ($/Tonne)

Bingaman-Specter

2012: $12/tonne

Europe Carbon-Trading

2012: $35.50/tonne

EIA Carbon Case

2010: $31/tonne

Lieberman-Warner

Possible $20 to $40/tonne

56

Reliability Pricing Model Auction

PJM RPM Auction ($/MW-day)

(1) 

All values are approximate and not inclusive of wholesale transactions.

(2) 

All

capacity

values

are

in

installed

capacity

terms

(summer

ratings)

located

in

the

areas.

(3) 

EMAAC

obligation

consists

of

load

obligations

from

PECO

and

BGS.

The

PPL

obligation begins January 2010 and ends December 2010.

(4)

Removing State Line from the supply in October 2007 reduces this

by 515 MW.

(5)

08/09 Capacity supply decreased due to roll-off of several purchase power agreements (PPAs).

(6)

In 09/10, obligation is reduced due to roll-off of part of ComEd auction load obligation in May

2009.

(7)

MAAC = Mid-Atlantic Area Council; APS = Allegheny Power System.

(8)

PECO PPA expires December 2010.

2007 / 2008

2008 / 2009

2009 / 2010

2010 / 2011

2011 / 2012

in MW

Capacity

(2)

Obligation

Capacity

(2)

Obligation

Capacity

(2)

Obligation

Capacity

(2)

Obligation

Capacity

(2)

Obligation

RTO

16,000

(4)

6,600-

6,800

14,500

(5)

6,600-

6,800

12,700

4,750-

4,950

(6)

12,700

0

23,200

0

Eastern MAAC

9,500

9,500-

9,800

(3)

9,500

9,550-

9,850

(3)

9,500

9,750-

9,950

(3)

MAAC + APS

(7)

1,500

0

MAAC

11,000

9,300-

9,500

(3)(8)

Exelon Generation Participation within PJM Reliability Pricing Model

(1)

197.67

174.29

40.80

111.92

148.80

102.04

191.32

191.32

174.29

110.00

RTO

Eastern MAAC

MAAC + APS

MAAC

2007/2008

2008/2009

2009/2010

2010/2011

2011/2012

57

Long-Run Marginal Cost of Electricity

0

50

100

150

200

250

0

5

10

15

20

25

30

35

40

45

50

CO2 Price ($/Metric Ton)

Combustion Turbine

Pulverized Coal

CCGT

Nuclear

Note:  CCGT = Combined Cycle Gas Turbine

Excluding energy efficiency, Nuclear is the least expensive generation option in a carbon-

constrained environment

58

Exelon Generation Operating EBITDA

2009

EBITDA

2009

Open EBITDA

(No Carbon)

$ Millions

~$4,100

~$3,900

2008

EBITDA

(2)

(1)

Open EBITDA assumes that existing hedges (including the PECO load, Illinois auction load, ComEd financial swap, nuclear fuel, and other sales) are priced at market prices as of

7/31/08.

(2)

EBITDA data is operating-based. Refer to the Appendix for a reconciliation of Operating Net Income to EBITDA.

(3)

Sensitivities

are

derived

by

changing

one

assumption

at

a

time

while

holding

all

else

constant.

Due

to

correlation

of

the

various

assumptions,

the

pre-tax

earnings

impact

calculated

by aggregating individual sensitivities may not be equal to the pre-tax earnings impact calculated when correlations between the various assumptions are also considered.

~$6,400

2009

Open –

2009

(1)

2008

(at 90%+ financially

hedged)

(at ~95% financially

hedged)

Open EBITDA plus upside from energy, capacity, and carbon drives

Exelon Generation’s value

52.50

76.00

125.00

131.50

9.75

2009 Open

EBITDA

(1)

Assumptions

10/31/08

Prices

98.00

NAAP Coal Price ($/ton)

72.00

WTI Oil ($/barrel)

42.00

NI-Hub ATC Price ($/MWh)

59.30

PJM W-Hub ATC Price

($/MWh)

7.30

Henry Hub Gas Price

($/mmBtu)

~$100M

+/-

$1/MWh Ni-Hub ATC Price

See following slide for fuel sensitivities

Power Price Revenue Sensitivities:

~$60M

+/-

$1/MWh PJM W-Hub ATC Price

(Pre-Tax Impact)

2009 Open EBITDA

(1)

Sensitivities

(3)

~$4M

+/-

$1/MWh PJM W-Hub ATC Price

~$5M

+/-

$1/MWh Ni-Hub ATC Price

(Pre-Tax Impact)

2009 EBITDA

Sensitivities

59

Current Market Prices

Units

2005 ¹

2006 1

2007 ¹

2008

5

2009

6

2010

6

2011

6

PRICES (as of October 31, 2008)

PJM West Hub ATC

($/MWh)

60.92 ²

51.07 ²

59.76 ²

68.77

59.32

62.88

63.21

PJM NiHub ATC

($/MWh)

46.39 ²

41.42 ²

45.47 ²

48.98

42.04

43.10

45.26

NEPOOL MASS Hub ATC

($/MWh)

76.65 ²

59.68

2

66.72 ²

81.38

68.97

73.67

74.28

ERCOT North On-Peak

($/MWh)

76.90 ³

60.87 ³

59.44 ³

72.58

58.93

66.83

67.88

Henry Hub Natural Gas

($/MMBTU)

8.85

4

6.74

4

6.74

4

8.92

7.33

8.03

8.15

WTI Crude Oil

($/bbl)

56.62

4

66.38

4

69.72

4

106.51

71.88

78.19

83.18

PRB 8800

($/Ton)

8.06

13.04

9.67

11.83

14.03

15.45

16.75

NAPP 3.0

($/Ton)

52.42

43.87

47.54

105.93

98.00

97.50

96.50

ATC HEAT RATES (as of October 31, 2008)

PJM West Hub / Tetco M3

(MMBTU/MWh)

6.30

6.98

7.68

6.98

7.13

6.88

6.83

PJM NiHub / Chicago City Gate

(MMBTU/MWh)

5.52

6.32

6.65

5.54

5.78

5.36

5.55

ERCOT North / Houston Ship Channel

(MMBTU/MWh)

8.21

8.28

7.80

7.32

7.04

7.19

7.26

(1)

2005, 2006 and 2007 are actual settled prices.

(2)

Real Time LMP (Locational Marginal Price).

(3)

Next day over-the-counter market.

(4)

Average NYMEX settled prices.

(5)

2008 information is a combination of actual prices through October 31, 2008 and market prices for the

balance of the year.

(6)

2009, 2010 and 2011 are forward market prices as of October 31, 2008.

~$12

-

$25/barrel WTI Oil Price

~($5)

+ $25/barrel WTI Oil Price

~$25

-

$15/ton NAAP Coal Price

~($12)

+ $15/ton NAAP Coal Price

~$70

-

$1/mmBtu Henry Hub Gas Price

~($45)

+ $1/mmBtu Henry Hub Gas Price

(Pre-Tax Impact)

2009 Open EBITDA Fuel Price Cost Sensitivities

60

50

60

70

80

90

100

110

10/07

11/07

12/07

1/08

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

50

60

70

80

90

100

110

120

130

140

150

10/07

11/07

12/07

1/08

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

7

7.5

8

8.5

9

9.5

10

10.5

11

11.5

12

10/07

11/07

12/07

1/08

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

30

35

40

45

50

55

60

65

70

75

10/07

11/07

12/07

1/08

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

Forward NYMEX Natural Gas

PJM-West and Ni-Hub On-Peak Forward Prices

PJM-West and Ni-Hub Wrap Forward Prices

2010 Ni-Hub

2011 Ni-Hub

2011 PJM-West

2010 PJM-West

2010

2011

Market Price Snapshot

Rolling 12 months, as of October 31, 2008. Source: OTC quotes and electronic trading system. Quotes are daily.

2010 Ni-Hub

2011 Ni-Hub

2011 PJM-West

2010 PJM-West

Forward NYMEX Coal

2010

2011

$8.03

$8.15

$81.15

$81.30

$73.65

$73.90

$54.37

$36.00

$53.42

$53.90

$33.20

$55.87

61

7.5

8.5

9.5

10.5

11.5

12.5

13.5

14.5

15.5

16.5

17.5

18.5

10/07

11/07

12/07

1/08

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

8

8.2

8.4

8.6

8.8

9

9.2

9.4

9.6

9.8

10

10/07

11/07

12/07

1/08

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

7

7.5

8

8.5

9

9.5

10

10.5

11

11.5

12

10/07

11/07

12/07

1/08

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

60

65

70

75

80

85

90

95

100

10/07

11/07

12/07

1/08

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

2011

2010

2010

2011

2010

2011

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2010

2011

ERCOT North On Peak Spark Spread

Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder

Market Price Snapshot

Rolling 12 months, as of October 31, 2008. Source: OTC quotes and electronic trading system. Quotes are daily.

$7.70

$7.84

$67.88

$66.83

$8.68

$8.66

$8.79

$8.89

62

Exelon Nuclear Fleet Overview

Fleet also includes 4 shutdown units:  Peach Bottom 1, Dresden 1, Zion 1 & 2.

(1)

Capacity based on ownership interest.

Average in-service time = 27 years

2011

42.6% Exelon, 56.4%

PSEG

2016, 2020

503, 491

(1)

W

PWR

2

Salem, NJ

Life of plant capacity

100% AmerGen

2014;

renewal filed

2008

837

B&W

PWR

1

TMI-1, PA

Dry cask

100% AmerGen

2009; renewal filed

2005

625

GE

BWR

1

Oyster Creek, NJ

Dry cask

50% Exelon, 50%

PSEG

Renewed: 2033,

2034

570, 570

(1)

GE

BWR

2

Peach Bottom, PA

Dry cask

75% Exelon, 25% Mid-

American Holdings

Renewed: 2032

650, 653

(1)

GE

BWR

2

Quad Cities, IL

Dry cask

100%

Renewed: 2029,

2031

869, 871

GE

BWR

2

Dresden, IL

2010

100%

2022, 2023

1138, 1150

GE

BWR

2

LaSalle, IL

Dry cask

100%

2024, 2029

1149, 1146

GE

BWR

2

Limerick, PA

Re-rack completed

2011

2013

Spent Fuel Storage/

Date to lose full core

discharge capacity

GE

W

W

Vendor

BWR

PWR

PWR

Type

1

2

2

Units

100% AmerGen

2026

1065

Clinton, IL

100%

2024, 2026

1183, 1153

Byron, IL

100%

2026, 2027

1194, 1166

Braidwood, IL

Ownership

License

Expiration /

Status

Net Annual

Mean Rating

MW 2008

Plant, Location

63

64

ComEd 2009 EPS Contribution

(1)

Estimated contribution to Exelon’s operating earnings guidance.

(2)

Disallowances recorded in September 2008 in connection with the ICC order in ComEd’s distribution rate case.

ComEd’s operating earnings are expected to increase in 2009 primarily due to continued

execution of its Regulatory Recovery Plan

2008e

(1)

RNF

O&M

Depreciation /

Amortization

Interest

Expense

$0.45 -

$0.55

$0.30 –

$0.35

$0.25

$0.01

($0.06)

2009e

(1)

Key Items:

Cost Efficiency Initiative

Rate Case Disallowance

(2)

Storms

Energy Efficiency

Inflation

Pension & OPEB

$ / Share

Key Items:

Distribution Rates

Energy Efficiency

Weather

$0.01

$0.05

$0.02

$0.01

($0.04)

($0.03)

($0.01)

$0.18

$0.04

$0.01

65

6.1

2.0

7.3

6.5

2.1

2.3

Transmission

Distribution

ComEd –

Moving Forward

Executing Regulatory

Recovery Plan

~9 –

10%

~ 45%

~7.3 –

8.8%

~ 45%

ROE

Equity

(1)

~5.0 –

6.0%

~

45%

•

Constructive ComEd rate cases including

the recent final rate order that provides

for $273.6 million increase in annual

distribution revenues

•

Illinois Power Agency proposed

procurement

plan

for

ComEd

-

first

procurement in Spring 2009

•

Actively promoting/implementing

efficiency, renewable energy, and

demand-side management programs

•

Studying innovative future test year

approach for distribution rate filing in

2009

8.1

8.6

9.6

2008e

2009e

2011

(Illustrative)

(2)

Average

Annual

Rate

Base

(1)

($ in Billions)

ComEd’s

earnings

are

expected

to

increase

as

regulatory

lag

is

reduced

over

time

through regular rate requests, putting ComEd on a path toward appropriate returns

(1)

Equity

based

on

definition

provided

in

most

recent

ICC

distribution

rate

case

order

(book

equity

less

goodwill).

Projected

book

equity

ratio

in

2008

is

58%.

(2)

Provided solely to illustrate possible future outcomes that are based on a number of different assumptions, all of which are subject to uncertainties and should not be

relied upon as a forecast of future results.

66

ComEd Executing on Regulatory

Recovery Plan

The ICC issued a final Order in ComEd’s distribution rate case –

granting a revenue increase of $273.6 million to take effect on

September 16, 2008:

(14)

345

359

Depreciation and Amortization

$(87)

274

361

Total Revenue Increase

3  

129

132

Other Revenues

(11)

987

998

O&M Expenses

(22)

10.30% ROE /   

45.04% Equity

10.75% ROE /

45.11% Equity

ROE / Cap Structure

$(43)

$6,694

$7,071

Rate Base

Impact on

Revenue

Increase

ICC Order

ComEd

Original

Request

($ in millions)

67

Illinois Power Agency Proposes ComEd

Procurement Plan

In September 2008, the Illinois Power Agency proposed its first

ComEd procurement plan, which will provide for energy procurement

for up to a three-year period

Auction Contracts

Financial Swap

3/08

RFP

Jun 2007

Jun 2008

Jun 2009

Jun 2010

Jun 2011

Jun 2012

Jun 2013

NOTE: For illustrative purposes

only.  Assumes constant load profile

each year. 

2009

2009

Future Procurement by Illinois Power Agency

2010

2010

2011

2012

2011

68

ComEd Load Growth Trends

Key Economic Indicators

Estimated Weather-Normalized

Residential Load Growth

Chicago

US

9/08 Unemployment rate

6.6%

6.1%

3rd

Qtr ‘08 annualized growth in

gross domestic/metro product

(0.1%)

(0.3%)

8/08 Home price index

(9.8%)

(16.6%)

2008

2009

Customer Growth

0.7%

0.6%

Average Use-Per-Customer

0.1%

(0.6%)

Total Residential

0.8%

0.0%

Small C&I

0.4%

0.4%

Large C&I

0.1%

(1.0%)

All Customer Classes

0.4%

(0.1%)

32

33

38

38

24

19

5

10

15

20

25

30

35

40

45

50

2004

2005

2006

2007

2008E

2009E

8,000

8,100

8,200

8,300

8,400

8,500

New Customers

Avg. Use Per Customer

ComEd Residential Load Growth Statistics

69

70

PECO 2009 EPS Contribution

(1) 

Estimated contribution to Exelon’s operating earnings guidance.

PECO’s 2009 operating earnings are expected to be comparable to 2008 due to

the gas distribution rate increase and lower bad debt expense, partially offset by

higher CTC amortization

$ / Share

RNF

O&M

Interest

Expense

$0.45 -

$0.55

$0.45 –

$0.50

$0.07

$0.04

$0.02

($0.10)

Amortization /

Depreciation

2008e

(1)

2009e

(1)

Key Items:

Gas

Rate

Case

$0.07

Weather

$0.03

Pricing/Customer

Mix

($0.02)

Key Items:

Bad Debt                                 

Cost Efficiency Initiative          

Inflation

Pension & OPEB                  

Regulatory / Post 2010         

Key Item:

Competitive Transition

Charge (CTC) Amortization      ($0.09)

$0.06

$0.02

($0.02)

($0.01)

($0.01)

71

2.8

2.9

3.1

0.5

0.6

1.7

0.9

1.1

1.1

1.2

0.7

Gas

CTC

Electric Transmission

Electric Distribution

PECO –

Moving Forward

Actively Engaged in Transition

•

Positive outcome of 2008 gas rate case

provides for increased gas revenues of

$76.5 million

•

Developing plans and programs to

implement energy efficiency, demand

response and smart meter provisions of

Act 129 (HB2200)

•

Transitioning through an orderly structure

to market-based rates

–

Working with the Governor, Legislature, and

PAPUC for post-transition rates and

structure

–

Power Procurement Plan filed 9/10/08 to

address post-transition plan beginning in

2011 along with mitigation alternatives

~9 –

11%

(3)

Not applicable due to

transition rate structure

Rate Making ROE

Equity

~50-52%

6.1

5.5

5.0

Average Annual Rate Base

(1)

($ in Billions)

2008e

2009e

2011

(Illustrative)

(2)

PECO provides a predictable but declining source of earnings to Exelon through the

remainder of the transition period

(1)

Rate base as determined for rate-making purposes.

(2)

Provided solely to illustrate possible future outcomes that are based on a number of different assumptions, all of which are subject to uncertainties and should not be

relied upon as a forecast of future results.

(3)

Assumes PECO is awarded 100% of potential requested revenue increases for rate cases filed during the planning period.

72

PECO Pursuing Regulatory Path

PECO’s procurement plan

for obtaining default service Post 2010

includes a portfolio of full requirements and spot products competitively

procured through multiple RFP solicitations

Mitigation plan

includes early staggered procurement, voluntary post-rate

cap  phase-in, gradual phase-out of declining block rate design, customer

education, enhanced retail choice program, and low-income rate design

changes

A Compact Fluorescent Light bulb rebate program for over 3 million bulbs

An enhanced web-based energy audit / bill analyzer program

Voluntary Residential Direct Load Control (air conditioning cycling)

program for 75,000 customers

Full and current cost recovery for the 3 programs

Default Service

Procurement and

Mitigation Filing

Early Phase-in Filing

Energy Efficiency

and Demand Side

Response Filing

Early phase-in proposal

provides a voluntary opt-in program for customers

to pre-pay towards 2011 prices

Requested expedited PAPUC approval to allow for implementation July 1,

2009

PECO’s third quarter 2008 regulatory filings address procurement, rate mitigation, and

energy efficiency –

allowing PECO to execute on its regulatory strategy

73

$107.89

$107.04

2.63

2.63

0.48

0.48

2.41

6.00

10.75

PECO Average Electric Rates

(1)

System Average Rates based upon Restructuring Settlement Rate Caps on Energy and Capacity increased from original settlement by 1.6%

to reflect the roll-in of increased Gross Receipts Tax and $0.02/kWh for Universal Service Fund Charge and Nuclear Decommissioning Cost

Adjustment.  System Average Rates also adjusted for sales mix based on current sales forecast.  Assumes continuation of current

Transmission and Distribution Rates.

2011

2008 –

2010

Energy / Capacity

Competitive Transition

Charge (CTC)

Transmission

Distribution

11.52¢

(1)

Unit Rates (¢/kWh)

Electric Restructuring

Settlement

~20%

13.86¢

Assumptions

Projected Rate Increase Based on

Average PPL Procurement  Results

(Illustrative)

•

2011 default service rate will reflect

associated full requirements costs and be

acquired through multiple procurements

•

Using the average results of completed

PPL procurements for 2010 and assuming

a 50/50 weighting of Residential and

Small

C&I

customers

produces

a

proxy

of

10.75¢/kWh. This will result in a system

average rate increase of ~20%

•

PECO’s 2011 full requirements price

expected to differ from PPL due, in part, to

the timing of the procurement (2011 vs.

2010) and locational differences

•

Rates will vary by customer class and 

may be impacted by legislation and

procurement model

Residential

Small C&I

Round 1, 7/2007

$101.77

$105.11

Round 2, 10/2007

$105.08

$105.75

Round 3, 3/2008

$108.80

$108.76

Average

PPL Procurement Results

Round 4, 10/2008

$112.51

$111.94

74

Pennsylvania Snapshot

•

Governor Rendell’s “Energy Independence

Strategy”, introduced in February 2007,

spurred legislative activity. 

–

Legislation Act 129 (HB 2200) dealing with

energy efficiency/ demand response,

procurement and smart meters passed by

General Assembly on October 8th

and signed

onto law by Governor on October 15th

–

Energy Fund Bill and Alternative Fuel Bill

passed in Spring 2008 session

–

Rate mitigation expected to be taken up in

next legislative session beginning January

2009

Current Status

•

Energy Efficiency(EE) and Demand Response (DR)

–

EE Targets of 1% reduction in consumption by

2011, 3% reduction by 2013

–

DR target of 4.5% reduction in peak demand by

2013

–

Up to $20 million in penalties for failure to achieve

targets

–

Full and current program cost recovery through

surcharge mechanism

–

Reduced consumption reflected in future rate

base proceedings

–

Spending cap equal to 2% of revenue

–

Procurement

–

Competitive procurement using auctions, RFPs

or

bilateral agreements

–

Prudent mix of spot, short term or long term

(defined as 4-20 years) contracts

•

Smart Meters

–

Utilities must file smart meter file plan with

PAPUC by August 2009

–

Required to furnish meters upon 1) customer

request, 2) for new construction, and 3) on a

depreciation schedule not to exceed 15 years

–

Base rate or surcharge recovery

Act 129 (HB 2200) Highlights

75

PECO Load Growth Trends

4.8

6.3

8.4

7.7

5.5

4.6

0

1

2

3

4

5

6

7

8

9

10

2004

2005

2006

2007

2008E

2009E

9,000

9,100

9,200

9,300

9,400

9,500

9,600

9,700

9,800

9,900

10,000

New Customers

Avg. Use Per Customer

PECO Residential Load Growth Statistics

Philadelphia

US

9/08 Unemployment rate

6.1%

6.1%

3rd

Qtr ‘08 annualized growth in

gross domestic/metro product

0.3%

(0.3%)

Key Economic Indicators

2008

2009

Customer Growth

0.4%

0.3%

Average Use-Per-Customer

1.9%

0.1%

Total Residential

2.3%

0.4%

Small C&I

(0.6%)

0.1%

Large C&I

1.0%

0.0%

All Customer Classes

1.1%

0.2%

Estimated Weather-Normalized

Residential Load Growth

76

Key Assumptions, Projected 2009 Credit

Measures &

GAAP Reconciliation

77

Key Assumptions

37.3

1.2

2.6

23.86

115.37

6.65

6.84

45.47

7.68

7.78

59.76

6.74

148,307

41,343

189,650

94.5

2007 Actual

37.2

0.4

1.1

82.39

169.09

5.50

9.00

50.00

6.95

10.00

70.00

9.00

137,200

41,100

178,300

93.8

2008 Est.

9.75

Chicago City Gate Gas Price ($/mmBtu)

11.00

Tetco M3 Gas Price ($/mmBtu)

37.2

Effective Tax Rate (%)

(4)

(0.1)

ComEd

0.2

PECO

Electric Delivery Growth (%)

(3)

106.13

PJM West Capacity Price ($/MW-day)

173.73

PJM East Capacity Price ($/MW-day)

5.40

NI Hub Implied ATC Heat Rate (mmbtu/MWh)

52.50

NI Hub ATC Price ($/MWh)

6.95

PJM West Hub Implied ATC Heat Rate

(mmbtu/MWh)

76.00

PJM West Hub ATC Price ($/MWh)

9.75

Henry Hub Gas Price ($/mmBtu)

136,300

Total Genco Market and Retail Sales (GWhs)

(2)

41,800

Total Genco Sales to PECO (GWhs)

178,100

Total Genco Sales Excluding Trading (GWhs)

93.1

Nuclear Capacity Factor (%)

(1)

2009 Est.

(1)

Excludes Salem

.

(2)

Includes

Illinois

Auction

sales

and

ComEd

swap.

(3)

Weather-normalized retail load growth.

(4)

Excludes results related to investments in synthetic fuel-producing facilities.

78

Projected 2009 Key Credit Measures

BBB

A-

BBB+

BBB-

S&P Credit

Ratings

(3)

BBB+

A

BBB

BBB+

Fitch Credit

Ratings

(3)

A3

A2

Baa2

Baa1

Moody’s Credit

Ratings

(3)

3.6x

3.8x

FFO / Interest

ComEd:

18%

16%

FFO / Debt

55%

59%

Rating Agency Debt Ratio

6.3x

3.0x

FFO / Interest

PECO:

36%

10%

FFO / Debt

52%

53%

Rating Agency Debt Ratio

30%

49%

Rating Agency Debt Ratio

108%

50%

FFO / Debt

21.3x

8.6x

FFO / Interest

Exelon

Generation:

54%

39%

7.0x

Without PPA &

Pension / OPEB

(2)

62%

Rating Agency Debt Ratio

25%

FFO / Debt

5.2x

FFO / Interest

Exelon

Consolidated:

With PPA & Pension /

OPEB

(1)

Notes: Projected credit measures reflect impact of Illinois electric rates and policy settlement.  Exelon, ComEd and PECO metrics exclude securitization debt.  See following slide for

FFO

(Funds

from

Operations)/Interest,

FFO/Debt

and

Adjusted

Book

Debt

Ratio

reconciliations

to

GAAP.

(1)

Reflects S&P updated guidelines, which include imputed debt and interest related to purchased power agreements (PPA), unfunded pension and other postretirement benefits

(OPEB) obligations, capital adequacy for energy trading, operating lease obligations, and other off-balance sheet debt.  Debt is imputed for estimated pension and OPEB

obligations by operating company.

(2)

Excludes items listed in note (1) above.

(3)

Current senior unsecured ratings for Exelon and Generation and senior secured ratings for ComEd and PECO as of 10/31/08.  On October 21, 2008, S&P put Exelon, ComEd,

PECO and Exelon Generation on Credit Watch with negative implications.

79

FFO Calculation and Ratios

FFO Calculation

= FFO

-

PECO Transition Bond Principal Paydown

+ Gain

on

Sale,

Extraordinary

Items

and

Other

Non-Cash

Items

(3)

+ Change in Deferred Taxes

+ Depreciation,

amortization

(including

nucl

fuel

amortization),

AFUDC/Cap.

Interest

Add back non-cash items:

Net Income

Adjusted Interest

FFO + Adjusted Interest

= Adjusted Interest

+ 7% of Present Value (PV) of Operating Leases

+ Interest

on

imputed

debt

related

to

PV

of

Purchased

Power

Agreements

(PPA), unfunded Pension and Other Postretirement Benefits (OPEB)

obligations,

and

Capital

Adequacy

for

Energy

Trading

(2)

,

as

applicable

-

PECO Transition Bond Interest Expense

Net Interest Expense (Before AFUDC & Cap. Interest)

FFO Interest Coverage

+ Capital

Adequacy

for

Energy

Trading

(2)

FFO

= Adjusted Debt

+ PV of Operating Leases

+ 100%

of

PV

of

Purchased

Power

Agreements

(2)

+ Unfunded

Pension

and

OPEB

obligations

(2)

+ A/R Financing

Add off-balance sheet debt equivalents:

-

PECO Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Adjusted Debt

(1)

FFO Debt Coverage

Rating Agency Capitalization

Rating Agency Debt

Total Adjusted Capitalization

Adjusted Book Debt

= Total Rating Agency Capitalization

+ Off-balance

sheet

debt

equivalents

(2)

-

Goodwill

Total Adjusted Capitalization

= Rating Agency Debt

+ ComEd Transition Bond Principal Balance

+ Off-balance

sheet

debt

equivalents

(2)

Adjusted Book Debt

= Total Adjusted Capitalization

+ Adjusted Book Debt

+ Preferred Securities of Subsidiaries

+ Total Shareholders' Equity

Capitalization:

= Adjusted Book Debt

-

Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Debt to Total Cap

Note: Reflects S&P guidelines and company forecast.  FFO and Debt related to non-recourse debt are excluded from the calculations.

(1)

Uses current year-end adjusted debt balance.

(2)

Metrics are calculated in presentation unadjusted and adjusted for debt equivalents and related interest for PPAs, unfunded Pension and OPEB obligations, and Capital

Adequacy for Energy Trading.

(3)

Reflects depreciation adjustment for PPAs and decommissioning interest income and contributions.

80

GAAP Earnings Reconciliation

Year Ended December 31, 2007

(18)

-

-

-

(18)

Nuclear Decommissioning obligation reduction

(11)

-

-

-

(11)

Sale of Genco’s

investments in TEG and TEP

72

-

-

-

72

Georgia Power tolling agreement

(130)

-

-

-

(130)

Termination of Stateline PPA

(5)

-

-

-

(5)

Settlement of a tax matter at Generation related to Sithe

$(115)

(63)

-

-

(87)

-

$35

Other

$2,923

(29)

14

280

(87)

101

$2,736

Exelon

$507

-

-

-

-

-

$507

PECO

$200

-

14

24

-

(3)

$165

ComEd

ExGen

(in millions)

-

City of Chicago settlement

256

2007 Illinois electric rate settlement

$2,331

2007 Adjusted (non-GAAP) Operating Earnings / (Loss)

34

Non-cash deferred tax items

-

Investments in synthetic fuel-producing facilities

104

Mark-to-market adjustments from economic hedging activities

$2,029

2007 GAAP Reported Earnings

Note: Amounts may not add due to rounding.

81

(1)

Amounts shown per Exelon share and represent contributions to Exelon's EPS.

(0.01)

-

-

-

(0.01)

Settlement of a tax matter at Generation related to Sithe

(0.04)

(0.08)

-

-

0.04

Non-cash deferred tax items

(0.14)

(0.14)

-

-

-

Investments in synthetic fuel-producing facilities

0.41

-

-

0.03

0.38

2007 Illinois electric rate settlement

(0.19)

-

-

-

(0.19)

Termination of State Line PPA

0.11

-

-

-

0.11

Georgia Power tolling agreement

Exelon

Other

(1)

PECO

(1)

ComEd

(1)

ExGen

(1)

$4.32

$(0.18)

$0.75

$0.30

$3.45

2007 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

(0.01)

-

-

-

(0.01)

Sale of Generation's investments in TEG and TEP

0.02

-

-

0.02

-

City of Chicago settlement

(0.03)

-

-

-

(0.03)

Nuclear decommissioning obligation reduction

0.15

-

-

-

0.15

Mark-to-market adjustments from economic hedging activities

$4.05

$0.04

$0.75

$0.25

$3.01

2007 GAAP Earnings Per Share

GAAP EPS Reconciliation

Year Ended December 31, 2007

82

2008/2009 Earnings Outlook

•

Exelon’s outlook for 2008/2009 adjusted (non-GAAP) operating

earnings excludes the earnings impacts of the following:

•

Mark-to-market adjustments from economic hedging activities

•

Unrealized gains and losses from nuclear decommissioning trust fund investments

primarily related to the AmerGen nuclear plants

•

Significant impairments of assets, including goodwill

•

Changes in decommissioning obligation estimates

•

Costs

associated

with

the

2007

Illinois

electric

rate

settlement

agreement,

including

ComEd’s previously announced customer rate relief programs

•

Costs associated with ComEd’s settlement with the City of Chicago

•

Certain costs associated with the proposed offer to acquire NRG Energy Inc.

•

Other unusual items

•

Significant future changes to GAAP

•

Both our operating earnings and GAAP earnings guidance are

based on the assumption of normal weather

83

Operating net income (loss)

+/-

Cumulative effect of changes in accounting principle

+/-

Discontinued operations

+/-

Minority interest

+   Income taxes

Income (loss) from continuing operations before income taxes and

minority

interest

+/-

Total other income and deductions (interest expense; equity in (losses) earnings

of investments; and other, net)

+   Depreciation and amortization

Earnings before interest, taxes, depreciation and amortization (EBITDA)

Reconciliation of Net Income to EBITDA

84

Exelon Investor Relations Contacts

Inquiries concerning this presentation

should be directed to:

Exelon Investor Relations

10 South Dearborn Street

Chicago, Illinois 60603

312-394-2345

For copies of other presentations,

annual/quarterly reports, or to be

added to our email distribution list

please contact:

Martha Chavez

Executive Admin Coordinator

312-394-4069

Martha.Chavez@ExelonCorp.com

Investor Relations Contacts:

Chaka Patterson, Vice President

312-394-7234

Chaka.Patterson@ExelonCorp.com

Karie Anderson, Director

312-394-4255

Karie.Anderson@ExelonCorp.com

Marybeth Flater, Manager

312-394-8354

Marybeth.Flater@ExelonCorp.com